Formation of hydrates is a well-known problem in subsea production systems for oil and gas. Several options are available to solve this problem. Traditionally, chemicals have been used. Recently, a more effective direct electric heating method is used for heating of the pipeline by forcing a high electric current through the pipeline. A subsea pipeline direct electrical heating cable is installed parallel to and connected to a distant end of the pipeline, as shown in WO 2004/111519 A1, for example.
A power system for providing a subsea pipeline direct electrical heating cable with power from a three-phase power grid has been described in WO 2010/031626 A1, for example.
The subsea pipeline direct electrical heating cable has a linearly decreasing voltage, from an input value at a power in-feed end to zero at the grounded, remote end. Consequently, the electric filed stress on the cable insulation also decreases linearly, from a normal operating stress at the power in-feed end to zero at the remote end.
A cable fault in the remote region may be initiated by a mechanical damage (e.g., a cut extending through the outer sheath and the insulation system), thus exposing the copper conductor to seawater. As the conductor is connected to ground at the remote end, the fault will shunt a remaining length from fault location to grounded end. The corresponding change in conductor current will be minute and extremely difficult to detect at the opposite end of a subsea pipeline direct electrical heating cable. A current measurement may be done even further upstream, making small changes even harder to detect. The conductor current in a subsea direct electrical heating system may be larger than 1000 A, and a fault current of 10 A through the physical fault will translate into a far smaller change at the in-feed end (e.g., due to phase shifting). Even with the best available current measuring equipment, cable faults near the remote end will therefore pass on undetected.
An electric current flowing out from the surface of a copper conductor and into seawater will cause rapid corrosion (e.g., alternative current corrosion) of the copper conductor, even at small current levels or voltage differences. If such a fault goes undetected, the final outcome will be a complete corrosion break of the copper conductor. A seawater filled gap is thus introduced between the two “conductor stubs,” but the electric impedance of this gap may not be sufficiently large to cause a detectable change in current at the in-feed end of the DEH system. As the gap will not be capable of withstanding the source voltage, an electric arc is then formed between the two “conductor stubs”. The temperature associated with such arcing is several thousand degrees Celsius, so a rapid meltdown of the copper conductor as well as any polymer in the vicinity will occur. The boiling temperature of seawater at most relevant water depths will be above the polymer melting points, so “water cooling” will not prevent the described melt-down from taking place.
The subsea pipeline direct electrical heating cable is commonly placed as close to the thermally insulated pipeline as possible. The thermal insulation will thus also be melted down by a fault, as described above. Once the steel pipeline is exposed to seawater, the steel pipeline will appear as an alternative, and probably low-impedance, return path for the fault current. As the copper conductor is continuously eroded away and widening the gap between the “stubs”, the pipeline will at some point in time become the lowest impedance return path. At that time, a new arc will be established between the conductor stub (e.g., in-feed side) and the steel pipeline. A rapid melt through of the pipeline's steel wall may result, and the pipeline contents may escape implying severe environmental pollution.
In WO 2007/096775 A2, a fault detection system for subsea pipeline direct electrical heating cables is provided. The system proposed is based on fiber optic elements included in the subsea pipeline direct electrical heating cables. Accordingly, the known fault detection system is not suitable for existing installations.
WO 2006/130722 A2 discloses an apparatus and method for determining a faulted phase resulting from a fault in a three-phase ungrounded power system. The known method includes comparing a phase angle of an operating phasor to a phase angle of a fixed reference phasor. The operating phasor is derived from a digitized signal sample of a plurality of measured signals of the power system. The known method also includes comparing a phase angle difference between the operating phasor and the fixed reference phasor to at least one threshold to determine the faulted phase. The fixed reference phasor may be a phase-to-phase voltage or a positive sequence voltage of the plurality of measured signals of the power system. The operating phasor may be a zero sequence current, a zero sequence voltage or a combination of a zero sequence current and a zero sequence voltage of the plurality of measure signals of the power system.
EP 0 079 504 A1 describes a method and an apparatus for detecting a single-phase-to-ground fault on a three-phase electrical power system, and for identifying a faulted phase. A single-phase-to-ground fault is correctly distinguished from other faults (e.g., including phase-to-phase-to-ground faults, even with transmission lines that utilize series capacitors) by taking into consideration the phase-to-phase voltage, which is in quadrature with the voltage to ground of the monitored phase.
US 2004/0032265 A1 discloses a double-ended distance-to-fault location system using time-synchronized positive-or-negative-sequence quantities for a three-phase transmission line.